1. Field of the Invention
The present invention pertains to the field of flow metering technology including a system and method for use in measuring production volumes including a multiphase mixture of discrete phases, e.g., a mixture including oil, gas, and water phases. More specifically, the system and method determine a density of the oil in the multiphase mixture to more efficiently measure a flow rate of the oil.
2. Statement of the Problem
It is often the case that a fluid flowing through a tubular member contains a plurality of phases, i.e., the fluid is a multiphase fluid. As used herein, the term xe2x80x9cphasexe2x80x9d refers to a type of fluid that may exist in contact with other fluids, e.g., a mixture of oil and water includes a discrete oil phase and a discrete water phase. Similarly, a mixture of oil, gas, and water includes a discrete gas phase and a discrete liquid phase with the liquid phase including an oil phase and a water phase. The term xe2x80x9cfluidxe2x80x9d is used herein in the context that fluid includes gas and liquids.
Special problems arise when one uses a flowmeter to measure volumetric or mass flow rates in the combined multiphase flow stream. Specifically, the flowmeter is designed to provide a direct measurement of the combined flow stream, but this measurement cannot be directly resolved into individual measurements of the respective phases. This problem is particularly acute in the petroleum industry where producing oil and gas wells provide a multiphase flow stream including unprocessed oil, gas, and saltwater. Commercial markets exist only for the hydrocarbon products.
It is a common practice in the petroleum industry to install equipment that is used to separate respective oil, gas, and water phases of flow from oil and gas wells. The producing wells in a field or a portion of a field often share a production facility for this purpose, including a main production separator, a well test separator, pipeline transportation access, saltwater disposal wells, and safety control features. Proper management of producing oil or gas fields demands knowledge of the respective volumes of oil, gas and water that are produced from the fields and individual wells in the fields. This knowledge is used to improve the producing efficiency of the field, as well as in allocating ownership of revenues from commercial sales of bulk production.
Early installations of separation equipment have included the installation of large and bulky vessel-type separation devices. These devices have a horizontal or vertical oblong pressure vessel together with internal valve and weir assemblies. Industry terminology refers to a xe2x80x98two-phasexe2x80x99 separator as one that is used to separate a gas phase from a liquid phase including oil and water. The use of a two-phase separator does not permit direct volumetric measurements to be obtained from segregated oil and water components under actual producing conditions because the combined oil and water fractions are, in practice, not broken out from the combined liquid stream. A xe2x80x98three-phasexe2x80x99 separator is used to separate the gas from the liquid phases and also separates the liquid phase into oil and water phases. As compared to two-phase separators, three-phase separators require additional valve and weir assemblies, and typically have larger volumes to permit longer residence times of produced materials for gravity separation of the production materials into their respective oil, gas, and water components.
Older pressure vessel separators are bulky and occupy a relatively large surface area. This surface area is very limited and quite expensive to provide in certain installations including offshore production platforms and subsea completion templates. Some development efforts have attempted to provide multiphase measurement capabilities in compact packages for use in locations where surface area is limited. These packages typically require the use of nuclear technology to obtain multiphase flow measurements.
Coriolis flowmeters are mass flowmeters that can also be operated as vibrating tube densitometers. The density of each phase may be used to convert the mass flow rate for a particular phase into a volumetric measurement. Numerous difficulties exist in using a Coriolis flowmeter to identify the respective mass percentages of oil, gas, and water in a total combined flow stream.
U.S. Pat. No. 5,029,482 teaches the use of empirically-derived correlations that are obtained by flowing combined gas and liquid flow streams having known mass percentages of the respective gas and liquid components through a Coriolis meter. The empirically-derived correlations are then used to calculate the percentage of gas and the percentage of liquid in a combined gas and liquid flow stream of unknown gas and liquid percentages based upon a direct Coriolis measurement of the total mass flow rate. The composition of the fluid mixture from the well can change with time based upon pressure, volume, and temperature phenomena as pressure in the reservoir depletes and, consequently, there is a continuing need to reverify the density value.
U.S. Pat. No. 4,773,257 teaches that a water fraction of a total oil and water flow stream may be calculated by adjusting the measured total mass flow rate for water content, and that the corresponding mass flow rates of the respective oil and water phases may be converted into volumetric values by dividing the mass flow rate for the respective phases by the density of the respective phases. The density of the respective phases must be determined from actual laboratory measurements. The ""257 patent relies upon separation equipment to accomplish separation of gas from the total liquids, and this separation is assumed to be complete.
U.S. Pat. No. 5,654,502 describes a self-calibrating Coriolis flowmeter that uses a separator to obtain respective oil and water density measurements, as opposed to laboratory density measurements. The oil density measurements are corrected for water content, which is measured by a water cut monitor or probe. The ""502 patent relies upon a separator to eliminate gas from the fluids traveling through the meter, and does not teach a mechanism for providing multiphase flow measurements when gas is part of the flow stream that is applied to the Coriolis flowmeter.
U.S. Pat. No. 5,535,532 describes multiple systems that measure the flow rates of oil, gas, and water. The ""532 patent calculates the flow rate of oil based on a known or assumed value for the density of oil. One problem with the ""532 patent is that none of the described systems calculate or measure the density of oil. The density of oil can be determined by taking a sample of the multiphase flow to a lab, which can be time consuming and expensive. The density of oil can also be assumed from previous data. However, the assumed density may not accurately represent the actual density of the oil.
Even three-phase separation equipment does not necessarily provide complete separation of the oil phase from the water phase. Water-cut probes are used to measure water content in the segregated oil phase because a residual water content of up to about ten percent typically remains in the visibly segregated oil component. The term xe2x80x98water-cutxe2x80x99 is used to describe the water content of a multiphase mixture, and is most often applied to a ratio that represents a relationship between a volume of oil and a volume of water in an oil and water mixture. According to the most conventional usage of the term xe2x80x98water-cutxe2x80x99, well production fluids would have a 95% water-cut when water comprises 95 out of a total 100 barrels of oil and water liquids. The term xe2x80x98water-cutxe2x80x99 is sometimes also used to indicate a ratio of the total volume of oil produced to the total volume of water produced. A term xe2x80x98oil-cutxe2x80x99 could imply the oil volume divided by the combined oil and water volume. As defined herein, the term xe2x80x98water-cutxe2x80x99 encompasses any value that is mathematically equivalent to a value representing water or oil as a percentage of a total liquid mixture including water and oil.
The present invention helps to solve the above problems that are outlined above by providing a method and system for performing multiphase flow measurements which do not require manual sampling or laboratory analysis of the production fluids in order to determine a density of oil components in the production fluids. The method and system are advantageously cheaper and more efficient than manual sampling. The method and system are also more accurate than prior systems.
One embodiment of the invention comprises a multiphase flow measurement system for performing multiphase flow measurements. The multiphase flow measurement system comprises a separator, a Coriolis flowmeter, a water-cut monitor, and a controller. The separator is configured to separate an incoming multiphase flow into a majority liquid component and a majority gas component. The majority liquid component is comprised of a water component and an oil component. The Coriolis flowmeter is configured to receive the majority liquid component and determine a density of the majority liquid component. The water cut monitor is configured to receive the majority liquid component and determine a water-cut of the majority liquid component. The controller is configured to communicate with the Coriolis flowmeter and the water-cut monitor. The controller is configured to determine if the majority liquid component includes entrained gas. If the majority liquid component is substantially free from entrained gas, then the controller is configured to process the water-cut and the density of said majority liquid component to determine a density of the oil component.
In one example, after the controller determines the density of the oil component, then the controller is further configured to measure a flow rate of the oil component based on the density of said oil component. The majority liquid component at this time could include entrained gas.
In another example, the multiphase flow measurement system further comprises a water trap configured to receive the majority liquid component and capture a sample of the water component. A hydrometer in the multiphase flow measurement system is configured to determine the density of the water component from the sample taken by the water trap. The controller is then configured to process the density of the water component, the water-cut, and the density of the majority liquid component to determine the density of the oil component.
In another example, the controller looks at the drive gain of the Coriolis flowmeter to determine if the majority liquid component includes entrained gas. The controller first calculates a drive gain of the Coriolis flowmeter. The controller then determines if the drive gain is less than a threshold value. If the drive gain is less than the threshold value, then the majority liquid component does not include entrained gas.
The invention can be further defined by the following aspects. One aspect of the invention is a method of performing multiphase flow measurements in flow environments including a liquid phase and a gas phase, said method comprising:
separating an incoming multiphase flow into a majority liquid component and a majority gas component, said majority liquid component comprising a water component and an oil component;
determining if said majority liquid component includes entrained gas; and
if said majority liquid component is substantially free from said entrained gas, then:
determining a water-cut of said majority liquid component;
determining a density of said majority liquid component using a Coriolis flowmeter; and
processing said water-cut and said density of said majority liquid component to determine a density of said oil component.
Another aspect comprises determining a density of said water component and processing said density of said water component, said water-cut, and said density of said majority liquid component to determine said density of said oil component.
Another aspect comprises capturing a sample of said water component using a water trap.
Another aspect comprises measuring said density of said water component from said sample using a hydrometer.
Another aspect comprises separating said incoming multiphase flow into said majority liquid component and said majority gas component using a vortex separator.
Another aspect comprises calculating a drive gain of said Coriolis flowmeter and determining if said drive gain is less than a threshold value.
Another aspect comprises measuring said water-cut using a microwave-based monitor.
Another aspect comprises measuring said water-cut using a capacitive-based monitor.
Another aspect comprises measuring said water-cut using a resistance-based monitor.
Another aspect comprises after determining said density of said oil component, measuring a flow rate of said oil component based on said density of said oil component, wherein said majority liquid component includes said entrained gas.
Another aspect comprises a multiphase flow measurement system for performing multiphase flow measurements in flow environments including a liquid phase and a gas phase, said multiphase flow measurement system comprising:
a separator configured to separate an incoming multiphase flow into a majority liquid component and a majority gas component, said majority liquid component comprising a water component and an oil component;
a Coriolis flowmeter configured to receive said majority liquid component and determine a density of said majority liquid component;
a water-cut monitor configured to receive said majority liquid component and determine a water cut of said majority liquid component; and
a controller configured to communicate with said Coriolis flowmeter and said water cut monitor, determine if said majority liquid component includes entrained gas, and if said majority liquid component is substantially free from said entrained gas, then said controller is further configured to process said water-cut and said density of said majority liquid component to determine a density of said oil component.
Another aspect is that said controller is further configured to receive a density of said water component and process said density of said water component, said water-cut, and said density of said majority liquid component to determine said density of said oil component.
Another aspect comprises a water trap configured to receive said majority liquid component and capture a sample of said water component.
Another aspect comprises a hydrometer configured to determine said density of said water component from said sample.
Another aspect is that said separator comprises a vortex separator.
Another aspect is that said controller determines if said majority liquid component includes said entrained gas by being further configured to calculate a drive gain of said Coriolis flowmeter and determine if said drive gain is less than a threshold value.
Another aspect is that said water-cut monitor comprises a microwave-based monitor.
Another aspect is that said water-cut monitor comprises a capacitive-based monitor.
Another aspect is that said water-cut monitor comprises a resistance-based monitor.
Another aspect is that said controller is further configured to measure a flow rate of said oil component based on said density of said oil component, wherein said majority liquid component includes said entrained gas.
Other salient features, objects, and advantages will be apparent to those skilled in the art upon a reading of the discussion below in combination with the accompanying drawings.